1. Field of the Invention
The present invention relates to the desulfurization of hydrocarbon streams. More specifically the present invention relates to desulfurization of hydrocarbon streams by converting organic sulfur compounds in the streams to hydrogen sulfide without added hydrogen.
2. Description of Prior Art
The production of high octane gasoline continues to be a major objective of refinery operations worldwide. The phase-out of lead and the movement to reformulate gasoline to improve air quality in the United States, Europe, and the Pacific Rim countries present a major challenge and opportunity in the refining industry. In the United States, the recent Clean Act Amendments define reformulated gasoline in terms of composition including oxygen, benzene, Rvp and total aromatics, and of performance standards containing reductions in VOC's and air toxics. More stringent requirements may be required in the future as indicated by California Air Resources Board proposals for tighter limitations on gasoline olefins, sulfur, Rvp, and distillation curve. In Europe, movements are underway to reduce allowable benzene from the current guideline of 5 vol % maximum. An interim reduction to 3% has been proposed. Also, sulfur may be restricted to 200 ppmw in Eurograde gasoline. In the Pacific Rim countries, octane shortfall may occur as lead additives are phased out, and several countries are considering reducing the amount of allowable benzene in gasoline. Japan now limits the amount of sulfur in gasoline to 150 ppmw or less. However, conventional desulfurization technologies consume hydrogen or require caustic wash placing additional burdens on these limited refinery resources.
Typically hydrotreating is used to convert sulfur compounds in hydrocarbon streams or fractions to hydrogen sulfide for removal from the fraction. Hydrotreating is also used to improve stability by saturating olefinic compounds in the stock being treated. Hydrotreating also may be employed to improve the quality of feed streams to other units such as naphtha reformers and cat crackers or product streams such as jet fuels and distillates. Hydrotreating of heavier crude fractions is also used to improve the quality of FCC feedstocks and to remove sulfur from residual fuel oil fractions.
Specifically, hydrotreating of FCC feedstocks may be considered as feed preparation and/or as a pollutant cleanup process, and is generally associated with improved product selectivity and product quality in cracking. Thus, higher conversion and gasoline yield, and lower selectivity to coke have commonly been reported in FCC cracking of hydrogenated stocks. Also, more favorable light gas distribution, including higher isobutane yields, has been observed. Improved quality of cracked products, ranging from gas through coke, notably in lower sulfur and nitrogen contents, allows meeting ultimate SO.sub.2 and NO.sub.x specifications.
More specifically, hydrotreating converts asphaltenes and potential coke-forming material and saturates polynuclear aromatic ring systems so that less coke is formed upon cracking. Much of the hydrogen consumption in hydrotreating can be related to saturation of polynuclear aromatics, and sulfur and nitrogen heterocyclics.
A hydrotreating process is generally carried out in a fixed bed single pass adiabatic reactor with feed preheat, hydrogen-recycle/compression and cooling quench capabilities, and feed effluent heat exchange capacity. Typically, the required auxiliary apparatus are high and low pressure separators, fractionators, and access to amine scrubbers to remove hydrogen sulfide and mercaptans. A supply of H.sub.2 may be cascaded from a catalytic reformer, but high hydrogen-consumption dictates construction of a hydrogen plant.
Sulfur is removed catalytically by hydrogenation of heterocyclic aromatic rings in which it is located. In lighter fractions, mild conditions may suffice for desulfurization. However, with heavier oils, the sulfur is deeply buried in the hydrocarbon, and a mild catalytic cracking is required to extract it.
Processing residua for fuels is especially difficult if large amounts of asphaltenes are present. These high molecular weight, often colloidal aggregates, are highly aromatic and tend to coke up catalysts. Their sulfur and metals are difficult to remove, and much hydrogen is consumed in their processing.
The prior art provides no simple alternative to these basic hydrogenative cleanup processes which require a capital intensive hydrogen plant, a hydrotreating reactor and other associated equipment.